Systems and methods for removing combustion products from a power generation cycle

Abstract

The present disclosure relates to a system for removing a pollutant from a power generation cycle that utilizes a high pressure circulating fluid. The system includes a first direct contact cooling tower configured to cool the high pressure circulating fluid and condense a fluid stream that removes SO.sub.2 from the circulating fluid. A first recirculating pump fluidly communicates with the first direct contact cooling tower. The first tower includes an outlet configured to circulate a cooled CO.sub.2 product stream, and a second direct contact cooling tower is configured to receive at least a portion of the cooled CO.sub.2 product stream from the outlet. The second direct contact cooling tower is configured to cool the CO.sub.2 product stream and condense a fluid stream that removes NO.sub.x from the CO.sub.2 product stream. A second recirculating pump fluidly communicates with the second tower. An associated method is provided.

Claims

1. A method for removing an acid gas from a power cycle product stream, the method comprising: carrying out a power production cycle; directing a product stream containing CO.sub.2, SO.sub.x, and NO.sub.x from the power production cycle into a first direct contact cooling tower; contacting the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x in the first direct contact cooling tower with a first counter-current circulating aqueous liquid stream; removing at least a portion of SO.sub.2 present in the product stream in the first direct contact cooling tower via reaction between the SO.sub.2 and NO.sub.2 in the product stream in the presence of the aqueous liquid stream; withdrawing from the first direct contact cooling tower a recycle stream containing CO.sub.2 and NO.sub.x; and delivering at least a portion of the recycle stream containing CO.sub.2 and NO.sub.x back into the power production cycle.

2. The method according to claim 1, wherein the first counter-current circulating aqueous liquid stream comprises H.sub.2SO.sub.4.

3. The method according to claim 1, wherein the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x contains at least 10 ppm NO.sub.x based on the total mass of the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x.

4. The method according to claim 1, wherein the NOx concentration in the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x is controlled within a range such that less than 50% by mass of the NO.sub.x in the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x is converted to HNO.sub.3 in the first direct contact cooling tower.

5. The method according to claim 1, wherein the recycle stream containing CO.sub.2 and NO.sub.x that is withdrawn from the first direct contact cooling tower includes at least 90% by mass of the NOx present in the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x that is introduced into the first direct contact cooling tower.

6. The method according to claim 1, wherein the recycle stream containing CO.sub.2 and NO.sub.x that is withdrawn from the first direct contact cooling tower includes substantially no SO.sub.2 or contains SO.sub.2 in an amount of less than 50 ppm based on the total mass of the recycle stream containing CO.sub.2 and NO.sub.x.

7. The method according to claim 1, wherein the concentration of NO.sub.x in the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x is adjusted by adding NOx upstream from the first direct contact cooling tower.

8. The method according to claim 7, wherein NO.sub.x is added upstream from the first direct contact cooling tower by combining a nitrogen source with a fuel and an oxidant in a combustor upstream from the first direct contact cooling tower.

9. The method according to claim 7, wherein NO.sub.x is added directly to the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x upstream from the first direct contact cooling tower.

10. The method according to claim 9, wherein the NO.sub.x that is added directly to the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x upstream from the first direct contact cooling tower is generated from ammonia.

11. The method according to claim 1, wherein the concentration of NO.sub.x in the product stream containing CO.sub.2, SO.sub.x, and NO.sub.x is adjusted by increasing or decreasing a discharge flow from a first recirculating pump that is configured to receive a liquid product stream from the first direct contact cooling tower and recirculate the liquid product stream into the first direct contact cooling tower.

12. The method according to claim 1, wherein at least a portion of the NO.sub.x in the recycle stream containing CO.sub.2 and NO.sub.x is directed back into the power production cycle.

13. The method according to claim 1, wherein the recycle stream containing CO.sub.2 and NO.sub.x is divided into a recirculating working fluid stream that is directed back into the power production cycle and a net CO.sub.2 product stream.

14. The method according to claim 1, further comprising: directing at least a portion of the recycle stream containing CO.sub.2 and NO.sub.x into a second direct contact cooling tower; contacting the recycle stream containing CO.sub.2 and NO.sub.x in the second direct contact cooling tower with a second counter-current circulating aqueous liquid stream; removing at least a portion of NO.sub.2 from the recycle stream containing CO.sub.2 and NO.sub.x in the second direct contact cooling tower via reaction between the NO.sub.2 and water; and withdrawing from the second direct contacting cooling tower a stream containing CO.sub.2.

15. The method according to claim 14, wherein the second counter-current circulating aqueous liquid stream comprises HNO.sub.3.

16. The method according to claim 14, further comprising adding O.sub.2 to the recycle stream containing CO.sub.2 and NO.sub.x prior to directing the recycle stream containing CO.sub.2 and NO.sub.x into the second direct contact cooling tower.

17. The method according to claim 14, wherein prior to directing at least a portion of the recycle stream containing CO.sub.2 and NO.sub.x into the second direct contact cooling tower, the recycle stream containing CO.sub.2 and NO.sub.x is compressed utilizing a compressor in the power production cycle.

18. The method according to claim 14, wherein the recycle stream containing CO.sub.2 and NO.sub.x is divided into a recirculating portion that is directed back into the power production cycle and a net production portion that is directed to the second direct contact cooling tower.

19. A system for removing an acid gas from a power cycle product stream, the system comprising: a transfer element configured to deliver a power cycle product stream containing CO.sub.2, SO.sub.x, and NO.sub.x from a component of a power cycle; a first direct contact cooling tower configured to receive the power cycle product stream containing CO.sub.2, SO.sub.x, and NO.sub.x from the component of the power cycle under reaction conditions such that at least a portion of SO.sub.2 is removed therefrom and a recycle stream containing CO.sub.2 and NO.sub.x is output from the first direct contact cooling tower; a first recirculating pump in fluid communication with the first direct contact cooling tower configured to receive a liquid stream from the first direct contact cooling tower and recirculate at least a portion of the liquid stream to the first direct contact cooling tower; and a transfer element configured to deliver at least a portion of the recycle stream containing CO.sub.2 and NO.sub.x to a component of the power cycle.

20. The system according to claim 19, further comprising: a second direct contact cooling tower configured to receive at least a portion of the recycle stream containing CO.sub.2 and NO.sub.x from the first direct contact cooling tower under reaction conditions such that at least a portion of NO.sub.2 in the recycle stream containing CO.sub.2 and NO.sub.x is removed therefrom and a stream containing CO.sub.2 is output from the second direct contact cooling tower; and a second recirculating pump in fluid communication with the second direct contact cooling tower configured to receive a liquid stream from the second direct contact cooling tower and recirculate at least a portion of the liquid stream to the second direct contact cooling tower.

21. The system according to claim 19, further comprising an O.sub.2 input positioned upstream from the second direct contact cooling tower and downstream from the first direct contact cooling tower.

22. The system according to claim 19, further comprising a compressor positioned upstream from the second direct contact cooling tower and downstream from the first direct contact cooling tower.

Description

BRIEF DESCRIPTION OF THE DRAWING(S)

(1) Having thus described the disclosure in the foregoing general terms, reference will now be made to accompanying drawings, which are not necessarily drawn to scale, and wherein:

(2) FIG. 1A illustrates a schematic flow diagram of a power generation system, which includes a high efficiency combustor and turbine in series in combination with a high pressure recirculating fluid, configured to remove acid gas pollutants from the system, according to one aspect of the present disclosure;

(3) FIG. 1B illustrates a schematic flow diagram of a power generation system, which includes a high efficiency combustor and turbine in series in combination with a high pressure recirculating fluid, configured to remove acid gas pollutants from the system, according to one aspect of the present disclosure;

(4) FIG. 2 illustrates a graphical representation of the removal time of SO.sub.x and NO.sub.x in the first and second direct contact reactor mass transfer columns respectively with respect to increasing concentration levels of NO at the entrance to a first direct contact reactor mass transfer column, according to one aspect of the present disclosure; and

(5) FIG. 3 illustrates a graphical representation of the residence time of NO.sub.x removal after full SO.sub.x removal with respect to a desired NO outlet concentration in a second direct contact reactor mass transfer column, according to one aspect of the present disclosure.

DETAILED DESCRIPTION

(6) The present disclosure will now be described more fully hereinafter with reference to exemplary aspects thereof. These exemplary aspects are described so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art. Indeed, the disclosure may be expressed in many different forms and should not be construed as limited to the aspects set forth herein; rather, these aspects are provided so that this disclosure will satisfy applicable legal requirements. As used in the specification, and in the appended claims, the singular forms a, an, the, include plural referents unless the context clearly dictates otherwise.

(7) The present disclosure is directed to a power generation system configured to remove pollutants from the power generation system. As shown in FIGS. 1A and 1B, a system 50 for removing particular acid gases from a power generation system 18, 19 may be configured to remove particular acid gas pollutants (e.g., SO.sub.x, NO.sub.x, and/or the like) from the power generation system 18, 19. In FIGS. 1A and 1B, Block 19 illustrates generic components of a power generation system, which may include in one aspect, a combustor, a turbine, and a heat exchanger. Likewise, Block 18 illustrates additional generic components of a power generation system such as, for example, a compressor and/or a pump. The power generation system 18, 19 can utilize a fuel gas such as, for example, a hydrocarbon fuel gas. In some aspects the utilized fuel may be considered an unprocessed or minimally processed sour or unsweetened gas containing methane and longer chain hydrocarbon molecules in addition to sulfur, nitrogen and/or other fuel derived impurities which may include hydrogen sulfide (H.sub.2S), carbonyl sulfide (COS), carbon disulfide (CS.sub.2), ammonia (NH.sub.3), hydrogen cyanide (HCN), and/or mercury (Hg), all of which are in a reduced form. In some aspects, the power generation system 18, 19 may utilize a fuel gas that predominantly includes carbon monoxide and hydrogen along with impurities, which may include hydrogen sulfide (H.sub.2S), carbonyl sulfide (COS), carbon disulfide (CS.sub.2), ammonia (NH.sub.3), hydrogen cyanide (HCN), and/or mercury (Hg), all of which are in a reduced form.

(8) The fuel gas may be produced by any known method. As an example for purposes of illustration only, the fuel gas may be produced in an oxygen based coal gasifier such as a GE-Texaco water quench gasifier, with complete ash removal followed by fuel gas cooling with heat transfer to the power cycle, condensed water removal and fuel gas compression to a pressure of, for example, approximately 320 bar.

(9) The fuel gas (regardless of whether it is formed as illustrated above or is an unprocessed or minimally processed sour or unsweetened gas as noted above) is burned in the combustor of the power generation system in a stream that includes an oxidant, which preferably is a combination of O.sub.2 and CO.sub.2 (in some embodiments, a mixture of approximately 25% O.sub.2 and 75% CO.sub.2 (molar)). This results in a combustion product that includes CO.sub.2, H.sub.2O, and O.sub.2. Preferably, the combustion product stream includes 2% (molar) excess O.sub.2. A relatively large quantity of recycled CO.sub.2 (e.g., at a pressure of approximately 300 bar and at a temperature of approximately 720 C.) is mixed with the combustion product (e.g., in the combustor) to produce a combined combustion product stream (e.g., at a temperature of approximately 1150 C. and a pressure of approximately 300 bar). This combustion product stream is reduced in pressure (e.g., to approximately 30 bar with a discharge temperature of approximately 750 C.) as it passes through the power generation system turbine. The stream is then subsequently cooled in a recuperative heat exchanger against a heating recycle CO.sub.2 stream. It is understood that the foregoing provides an exemplary set of process conditions, and temperatures, pressures, etc. may be adjusted as necessary.

(10) Stream 4 leaves the cold end of a recuperative heat exchanger in Block 19 at a substantially reduced temperature (e.g., about 65 C.) and pressure (e.g., about 29 bar). At this point the composition of the stream is predominantly CO.sub.2 with a quantity of water (H.sub.2O), which is substantially in the liquid phase (e.g., about 85% by weight) with some quantity remaining in the vapor phase. Additionally, the stream 4 contains oxidized compounds of sulfur and nitrogen (SO.sub.x and NO.sub.x) with other trace components such as mercury (Hg) derived from oxidation of the impurities in the fuel gas.

(11) The combustion product stream exiting Block 19 can include a content of NO.sub.x or it may be substantially free of NOx. It is desirable to control the NOx content in stream 4 so that the NOx content is sufficiently high to react with SO.sub.x as further described herein. In various embodiments, the combustion product stream (e.g., stream 4) that enters a first direct contact reactor mass transfer column 30 (as described below) can particularly comprise CO.sub.2, SO.sub.x, and NO.sub.x. It is understood that the term SO.sub.x indicates the presence of any sulfur oxide and is not limited to a particular sulfur oxide unless otherwise specifically indicated (such as reference to a SO.sub.x containing stream that particularly includes SO.sub.2). A stream containing SO.sub.x may contain a single sulfur oxide species or a mixture of sulfur oxide species. It is likewise understood that the term NO.sub.x indicates the presence of any nitrogen oxide and is not limited to a particular nitrogen oxide unless otherwise specifically indicated (such as reference to a NO.sub.x containing stream that particularly includes NO.sub.2). A stream containing NO.sub.x may contain a single nitrogen oxide species or a mixture of nitrogen oxide species. Reference to acid gas removal can particularly indicate removal of one or both of SO.sub.x and NO.sub.x.

(12) As shown in FIGS. 1A and 1B, the power generation system 18, 19 with an acid gas pollutant removal system 50 may include two direct contact reactor mass transfer columns. A first mass transfer column 30 may be configured to remove SO.sub.2 in the form of H.sub.2SO.sub.4 from the net CO.sub.2 product stream, while the second mass transfer column 40 may be configured to remove NO and/or NO.sub.2 in the form of HNO.sub.3 from the net CO.sub.2 product stream external from the primary recirculating flow. In some aspects, the second mass transfer column 40 may be configured to remove NO and/or NO.sub.2 in the form of HNO.sub.3 from the net CO.sub.2 product stream before the high pressure recirculating fluid is introduced to a compressor element 18 of the power generation system, as shown in FIG. 1A. In another aspect, as illustrated in FIG. 1B, the second mass transfer column 40 may be configured to remove NO and/or NO.sub.2 in the form of HNO.sub.3 from the net CO.sub.2 product stream after the high pressure recirculating fluid is introduced to a compressor element 18 of the power generation system. The necessary components for this mass transfer, including the NO.sub.x gas phase catalyst, are present in the process fluid stream 4 that enters the first mass transfer column 30 where the SO.sub.2 is removed as H.sub.2SO.sub.4. According to some aspects, these components include SO.sub.2, NO, NO.sub.2, O.sub.2, and H.sub.2O.

(13) According to one aspect, stream 4 enters the base of the first mass transfer column 30, which may be a multi-stage direct contact counter-current liquid/vapor contacting column and may include internal contacting means such as trays, structured packing, random dumped packing, and/or the like. The first mass transfer column 30 has a bottom outlet pipe 6 which feeds either a net liquid product stream 7 or a first circulating pump 31 via an inlet line 8. The first circulating pump discharge line 9 enters a first water cooled heat exchanger 22, which discharges a cooled liquid stream 10 to the top of the first mass transfer column 30.

(14) In some aspects, the first mass transfer column 30 cools the inlet CO.sub.2 rich stream 4 from an exemplary temperature of approximately 65 C. against the cooled, recirculating fluid flow stream 10 falling counter-currently through internal contacting media to approximately near the ambient temperature. In particular, the CO.sub.2 is cooled to a minimum temperature that approaches the temperature of the cooling water. According to one exemplary aspect, the CO.sub.2 is cooled to about 16 C., while the cooling water approaches a temperature of approximately 13 C. As the inlet CO.sub.2 stream flows upward through the contacting media, the stream cools to near ambient temperature, water further condenses, and pollutant removal reactions occur. These pollutant removal reactions proceed first in the gas phase through the oxidation of NO to NO.sub.2 using remaining excess O.sub.2 in the inlet CO.sub.2 rich stream 4. Subsequently, SO.sub.2 is oxidized by NO.sub.2 to form SO.sub.3 and NO. Third, SO.sub.3 reacts with water (H.sub.2O) to form H.sub.2SO.sub.4 in the liquid phase, thereby removing SO.sub.2. NO acts as a gas phase catalyst in this process. The pollutant removal reactions involved are detailed in the equations below:
NO+1/2O.sub.2NO.sub.2Eq. G
NO.sub.2N.sub.2O.sub.4Eq. H
2NO.sub.2+H.sub.2OHNO.sub.2+HNO.sub.3Eq. I
3HNO.sub.2HNO.sub.3+2NO+SO.sub.3Eq. J
NO.sub.2+SO.sub.2NO+SO.sub.3Eq. K
SO.sub.3+H.sub.2OH.sub.2SO.sub.4Eq. L
These reactions are well understood as the mechanism of the Lead Chamber Process for sulfuric acid production. Additionally, the reactions can be described, as follows: Eq. G is gas phase, kinetically controlled; Eq. H is gas phase, equilibrium controlled with fast kinetics; Eq. I is liquid phase, kinetically controlled; Eq. J is liquid phase, equilibrium controlled with fast kinetics; Eq. K is gas phase, equilibrium controlled with fast kinetics; and Eq. L is dissolution in the aqueous phase which can be designed within a contactor to be a sufficiently fast process.

(15) At the elevated pressure of approximately 29 bar in the presence of excess liquid water and a partial pressure of O.sub.2 of approximately 0.58 bar and with about 100 to about 2000 ppm SO.sub.2 and about 20 to about 2000 ppm NO.sub.x present in stream 4, these reactions proceed spontaneously and rapidly. Additionally, the system is controlled to ensure that the concentration of SO.sub.2 in stream 11 exiting the top of the first mass transfer column 30 is below about 50 ppm while the concentration of HNO.sub.2 and HNO.sub.3 in the net product liquid stream 7 is below about 1%.

(16) In one aspect, these concentrations are obtained by controlling the inlet concentration of NO.sub.x in stream 4 and/or by controlling the discharge flow 9 from the first circulating pump 31, which provides for the liquid to vapor ratio, and hence the separation efficiency in the first mass transfer column 30, to be adjusted. In another aspect, the concentration of NO.sub.x in the inlet CO.sub.2 rich stream 4 can be adjusted while the discharge flow 9 from the first circulating pump 31 remains constant so as to ensure the concentration of SO.sub.2 in stream 11 exiting the top of the first mass transfer column 30 and/or the concentration of HNO.sub.2 and HNO.sub.3 in the net product liquid stream 7 are suitable concentrations.

(17) According to some aspects, as shown in FIG. 1A, the discharge CO.sub.2 product stream 11 leaving the top of the first mass transfer column 30 may be divided. For example, as shown in FIG. 1A, the bulk of the CO.sub.2 product stream 11 is diverted as the recycled, recirculating fluid stream 1A, which enters the compression and pumping elements 18 of the power generation system 19, while the net product stream 2A enters a second mass transfer column 40. According to another aspect, as shown in FIG. 1B, the entire discharge CO.sub.2 product stream 11 leaving the top of the first mass transfer column 30 may be fed to the compression and pumping element 18 of the power generation system as the recycled, recirculating fluid stream 1B. After the recycled, recirculating fluid stream passes through at least one compression and/or pumping element 18 of the power generation system, the high pressure, recirculating working fluid 3 may be divided such that the net product stream 2B enters the second mass transfer column 40 after passing through at least one compression element 18 of the power generation system. The design of the second mass transfer column 40 provides for sufficient contacting time and separation efficiency for a sequence of reactions, which lead to the formation of nitric acid. The second mass transfer column 40 may include a bottom outlet liquid stream 12, which may be divided into a nitric acid product stream 13 and a nitric acid recycle stream 14. Said nitric acid streams understood to be aqueous streams with varying nitric acid content. In one aspect, the nitric acid, recycle stream 14 passes through a second circulating pump 41. The discharge flow 15 from the second circulating pump 41 is fed into a water and/or ambient air cooled heat exchanger 23, which produces a cooled inlet dilute nitric acid stream 16 to the second mass transfer column 40.

(18) In some aspects, the second mass transfer column 40 includes a second contacting section above the inlet point of the cooled dilute nitric acid stream 16. The second contacting section disposed above the inlet point of the cooled dilute nitric acid stream 16 may be irrigated with a pure water inlet stream 24. In one aspect, the flow rate of the pure water inlet stream 24 may be adjusted to obtain the desired HNO.sub.3 concentration in the nitric acid product stream 13. The flow rate may also function to effectively remove acid carry-over in the final CO.sub.2 net product stream 17. The final CO.sub.2 net product stream 17 will be substantially free of acid particulates and will have a low specified concentration of SO.sub.2 and NO.sub.x.

(19) In one aspect, the set of mass transfer reactions may be accomplished by the first direct contact reactor mass transfer column 30 creating sufficient gas to liquid contact so as to allow SO.sub.3 formed in the gas phase to be quickly and efficiently converted to H.sub.2SO.sub.4 in the liquid phase. The first mass transfer column 30 may be a column that includes structured and/or random packing and/or distillation trays with a counter-flow arrangement of gas and liquid. Additionally, the first mass transfer column 30 may include a bottom inlet for receiving the inlet CO.sub.2 rich stream 4 and a top inlet for receiving the cooled recycle dilute acid stream 10. Such an arrangement for the first mass transfer column 30 may provide a closed loop cooling fluid, which recirculates through an indirect heat exchanger 22. In some aspects, heat removed in the first mass transfer column 30 may be transferred to an ambient temperature cooling means, such as a cooling water circulating system, which may include a cooling tower and/or a forced convection fan-air cooler.

(20) Additionally, the first mass transfer column 30 may include an efficient demister disposed above the contacting section. The demister may be configured to remove entrained dilute H.sub.2SO.sub.4 from the discharge CO.sub.2 product stream 11 so as to protect downstream compression equipment from corrosion; solutions containing H.sub.2SO.sub.4 have a tendency to form troublesome mists. Alternatively, an additional section of contacting media may be installed and irrigated with a pure water stream to dilute the acid particulate and/or remove carry-over of acid particulate. An additional section of contacting media may provide for optimization of gas to liquid contact, which may accelerate mass transfer reactions that produce sulfuric acid, may limit the need for an additional cooling medium, and may condense remaining combustion derived H.sub.2O from the recirculating stream following high-grade heat recovery from the exhaust stream via the recuperative heat exchanger in the power generation system. The optimization of gas to liquid contact, limiting the need for additional cooling medium, and/or condensing remaining combustion derived H.sub.2O desirably occur within a reasonable column size and residence time.

(21) According to some aspects, conditions within the combustor of the power generation system 19 provides for a small production of NO by combining nitrogen, nitrogen-containing components in the fuel, and/or nitrogen derived from air ingress through system seals with excess oxygen at typical combustion temperatures of about 1500 C. to about 2500 C., typical combustion pressures of about 100 bar to about 500 bar, and excess O.sub.2, which may have a composition ranging about 0 mol % to about 5 mol % O.sub.2 following combustion and mixing with recycled high pressure CO.sub.2. In one aspect, higher flame temperatures may be generally desired as the thermal NO formation mechanism may dominate the production of NO. The conservation of this quantity of NO is desirable as elevated concentrations of NO assist and accelerate the removal reactions of SO.sub.2 to H.sub.2SO.sub.4 in the first mass transfer column 30 to proceed at sufficient rates. Conservation of NO produced from the combustor may be accomplished via design considerations such as, for example, by the accumulation of NO within a semi-closed loop system and/or by minimizing the conversion of gaseous NO.sub.2 (formed by reaction of NO and O.sub.2) to aqueous HNO.sub.3. The accumulation of NO in a semi-closed loop system may be provided by the inherent design of the power generation system 18, 19, and the minimization of gaseous NO.sub.2 to aqueous HNO.sub.3 conversion may be accomplished by matching the column residence time of the first mass transfer column 30 to selectively remove SO.sub.2, as described herein.

(22) In one aspect, the NO concentration may be kept high via careful design of the direct contact means within the first mass transfer column 30 so as to have a residence time which minimizes the conversion of NO.sub.2 to HNO.sub.2 and/or HNO.sub.3. In particular, it has been observed that while SO.sub.2 exists in the cooled turbine exhaust, the NO.sub.2, which is formed by the oxidation of NO with O.sub.2, is immediately converted back to NO by reacting with SO.sub.2. The immediate conversion of the NO.sub.2 back to NO thereby preserves a high concentration of gas phase catalyst. In this regard, once a substantially high quantity of SO.sub.2 has been permanently removed from the gas phase by conversion of SO.sub.2 to H.sub.2SO.sub.4 in the liquid phase, a subsequent sequence of reactions occur in which NO.sub.2 dissolves in water to form HNO.sub.2 and HNO.sub.3. Additionally, one desirable aspect provides for conditions in the first mass transfer column 30 to convert a lesser amount of NO to HNO.sub.2 and/or HNO.sub.3 by the second reaction sequence in the first mass transfer column 30. For example, conditions in the first mass transfer column 30 may provide for a CO.sub.2 rich discharge stream 11 that exits the first mass transfer column where less than 30% by mass of the NO.sub.x is converted to HNO.sub.2 and/or HNO.sub.3. In some aspects, about less than 5% of the NO.sub.x is converted to HNO.sub.2 and/or HNO.sub.3 before the high pressure recirculating working fluid exits the first mass transfer column. Converting a greater amount of NO to HNO.sub.2 and/or HNO.sub.3 would reduce the concentration of NO in the inlet CO.sub.2 rich stream 4 that exits the turbine of the power generation system 19 and enters the first mass transfer column 30, thereby lowering the conversion rate of SO.sub.2 to H.sub.2SO.sub.4. Furthermore, any HNO.sub.2 and/or HNO.sub.3 converted leaves the first mass transfer column 30 in the sulfuric acid liquid stream 7 and can be subsequently neutralized. The actual amount of NO.sub.x conversion is tunable based on the exact process needs.

(23) The isolated removal of SO.sub.2 in the first mass transfer column 30 further may accumulate sulfuric acid (and/or trace HNO.sub.3) in the recirculating fluid of the first mass transfer column 30. In one aspect, a small HNO.sub.3 concentration in the sulfuric acid liquid stream may exist, but the concentration amount can be controlled to a minimum. Reaction of HNO.sub.3 with mercury derived from the coal takes place primarily in the second mass transfer column 40 forming mercuric nitrate. The mixed H.sub.2SO.sub.4+HNO.sub.2+HNO.sub.3 may also convert other low concentration impurities to soluble salts, which may be removed in the liquid acid phase. Additionally or alternatively, the remaining sulfuric acid created within the first mass transfer column 30 can be reacted with a slurry of crushed limestone and/or any other suitable alkaline compound in water so as to convert H.sub.2SO.sub.4 to calcium sulfate. The converted calcium sulfate may be removed as a solid and used commercially and/or disposed of. Additionally, CO.sub.2 may be released during this step, producing a pure product that can be combined with the net power cycle CO.sub.2 stream 1 and/or diverted to a common or separate system venting stream 17 to a pipeline 21 for transport.

(24) In some aspects, the NO produced inherently within the process may be insufficient to catalyze a sufficient removal of SO.sub.2 from the process gas. According to one aspect, an NO addition stream 5 including substantially NO can be introduced to the power generation system 5. In some aspects, the NO may be produced, for example, by the oxidation of ammonia (NH.sub.3) with a mixture including oxygen and/or carbon dioxide over a catalyst in a NO producing unit 20. Addition of pure N.sub.2 to the power generation system 18, 19 may be undesirable because the addition may lead to drastic effects on system dynamics. For example, the addition of pure N.sub.2 may change important working fluid properties, such as the compressibility of the fluid. By controlling the inlet concentration of NO to the first mass transfer column 30 via the addition of NO through the NO addition stream 5, the required removal time of SO.sub.2 from the process gas can be controlled to fall within a desired column residence time. Central to this control mechanism is that NO may not be consumed until substantially all of the SO.sub.2 is removed. As such, the first reactor mass transfer column 30 may be tuned and/or designed by careful control of the inlet NO concentration to remove nearly all of the SO.sub.2 (e.g., 99.99%) without significant removal of NO. The specific NO concentration may be determined by the inlet SO.sub.2 concentration as well as the designed residence time for SO.sub.2 removal. For example, according to one aspect, the NO concentration at the inlet to the first mass transfer column 30 may be about 152 ppm and the SO.sub.2 concentration at the inlet to the first mass transfer column 30 may be about 1318 ppm. According to some aspects, the reflux ratio in both the first mass transfer column 30 and/or the second mass transfer column 40 may be controlled by controlling the flow-rates in the first and/or second circulation pumps 31, 41. In some aspects, one design consideration of the power generation system may include the column residence time, which may be optimized such that when the SO.sub.2 removal is complete and the gas phase is separated from the liquid phase, the conversion of NO to HNO.sub.2 and/or HNO.sub.3 may not occur.

(25) In one exemplary power generation system 18, 19 that includes a recirculating process fluid, an amount of NO can be conserved within the process stream by tuning and/or configuring the column residence time and concentrations of species at the inlet of the first mass transfer column 30 so that a desired removal efficiency of SO.sub.2 is achieved within the first mass transfer column 30 while permitting NO to remain in the discharge CO.sub.2 product stream 11 at the outlet of the first mass transfer column 30. According to one exemplary aspect, the first column residence time is about 30 seconds and the NO concentration at the exit of the first column is about 155 ppm. In this regard, an accumulation effect occurs, which creates an elevated NO concentration within the recycling fluid stream 1, which thereby may reduce the quantity of NO addition required from the NO producing unit 20 for sustaining the same SO.sub.2 removal rate in the first direct contact reactor mass transfer column 30. This accumulation effect has particular impact in systems where combustion results in elevated concentrations of SO.sub.2 thereby allowing for the removal time to be substantially reduced by elevating the concentration of NO within the system.

(26) In some aspects, following cooling and SO.sub.2 removal in the first direct contact reactor mass transfer column 30 of the power generation system 5, the discharge CO.sub.2 product stream 11 may be split into two streams and compressed to a pressure ranging from approximately 100 bar to approximately 500 bar. A minor stream dilutes an oxygen stream, forming the oxidant mixture used in the combustor, while a major stream is heated in the recuperative heat exchanger of the power generation system 19 to a temperature ranging from about 500 C. to about 800 C. and mixes with the combustor product gas forming the turbine inlet flow. Under these conditions virtually no destruction of NO occurs due to conversion of NO to N.sub.2 and O.sub.2 and/or the formation of NO by a reaction between N.sub.2 and O.sub.2. The amount and concentration of NO in the recuperated, cooled inlet CO.sub.2 rich stream 4 entering the first mass transfer column 30 may be higher than the concentration and amount leaving the first mass transfer column 30 and entering the recycling fluid stream 1 as a small amount of HNO.sub.3 is formed in the first mass transfer column 30 and the NO.sub.x present in the net CO.sub.2 product stream 2 enters the second mass transfer column 40.

(27) In addition, the design of the first and second mass transfer columns 30, 40 ideally will be such that the gas residence time will result in reasonable reaction conditions for the power generation system 18, 19 operating over a full operational range from a maximum output to a minimum turndown. For example, at a maximum turndown (e.g. 50% turbine flow), the column residence time is doubled, which may cause substantially more NO loss. However, the increased time for reactions may provide for a lower NO concentration in the inlet gas, which may still allow for the desired SO.sub.2 removal. This NO concentration may be supplemented via addition and accumulation in manners discussed herein.

(28) According to one exemplary aspect, the second mass transfer column 40 may be smaller than the first mass transfer column 30 and may be inserted in the net CO.sub.2 product stream of the power generation system 18, 19. Additionally, the smaller, second mass transfer column 40 may employ similar reactions and/or design considerations as the first mass transfer column 30 such that the smaller second mass transfer column 40 is also configured to remove SO.sub.2. The smaller, second direct contact reactor mass transfer column 40 may then subsequently alter the NO concentration to a desired downstream NO concentration, and may additionally or alternatively produce HNO.sub.2 and HNO.sub.3 during the process. The column may operate at a similar pressure to the first direct contact reactor, or at a substantially elevated pressure, following a compression step or series of compression steps. According to another aspect, the second mass transfer column 40 may operate at a similar temperature to that of the first mass transfer column 30 or at a substantially elevated temperature compared to the first mass transfer column, and may depend on the requirements for the final CO.sub.2 net product stream 17.

(29) The design of the first and second mass transfer columns 30, 40 may be influenced by the removal rate characteristics of SO.sub.2 and NO. For example, SO.sub.2 removal accelerates to an approximately 100% removal rate with increasing residence time, pressure, and NO concentration in the first mass transfer column 30. Thus, high inlet NO concentration may be desired to increase the SO.sub.2 removal rate. For example, FIG. 2 illustrates a graph showing that given a fixed residence time, the removal time for removing SO.sub.2 in the first mass transfer column 30 decreases as the NO concentration increases. FIG. 3 illustrates that the NO removal time with respect to a desired outlet concentration limit asymptotically approaches a fixed required removal time once SO.sub.2 has been substantially removed. This indicates that even at high levels of accumulation of NO, the additional time required for NO removal to a desired limit at the second mass transfer column 40 eventually approaches an asymptotic time, while the removal time of SO.sub.2 in the first mass transfer column 30 invariably decreases with the addition of excess NO. This implies that an addition of NO to increase the removal rate of SO.sub.2 in first mass transfer column 30 can be sustained in the second mass transfer column 40, which can be tuned and/or designed to the asymptotic removal time plus a relevant safety factor. In some aspects, the removal of NO.sub.x in the second contactor may be further accelerated by the addition of additional oxygen to the column.

(30) In other aspects the removal of NO.sub.x in the second column 40 may be accelerated by compression of stream 2A and/or 2B to a pressure above that of the first column 30 before entering the second column. This will accelerate the conversion of NO to NO.sub.2 as shown in Eq. G such that the removal reactions are driven more quickly to completion. The exact discharge pressure of this compressor may be adjusted to as to enact the required removal in the second column 40. Such embodiments are illustrated in FIG. 1A wherein compressor 62 is present in line 2A between Block 18 and the second column 40. The compressor can be optional. Alternatively, in relation to FIG. 1B, the entire content of the recycle stream containing CO.sub.2 and NO.sub.x can be input to the power production system in Block 18 where it can undergo compression. Accordingly, stream 2B may be taken directly from Block 18 at any pressure to be delivered to the second column 40.

(31) In some embodiments, it can be desirable to add additional oxygen to the stream prior to entry into the second column 40. As illustrated in FIG. 1B, an oxygen source 60 is positioned to supply oxygen via line 61a to the stream 2B prior to entry into the second column 40. It is understood that such elements for adding oxygen likewise may be applicable to the addition of oxygen to line 2A in FIG. 1A. The oxygen source can be optional. In other aspects an addition of excess oxygen and a series of recompression can be enacted in order to further accelerate removal of NOx.

(32) Aspects of the present disclosure are more fully illustrated by the following example(s), which are set forth to illustrate certain aspects of the present disclosure and are not to be construed as limiting thereof.

Example 1

(33) An evaluation was performed in relation to a power generation system that utilizes the oxy-combustion of a carbonaceous fuel to power a fully recuperated, trans-critical carbon dioxide Brayton power cycle. This arrangement, in various aspects, inherently captures CO.sub.2 at a sequestration and/or pipeline ready pressure. In aspects where the concentrations of sulfur and nitrogen are low in the combustion fuel, CO.sub.2 can be captured using minimal post-treatment steps. Thus, the CO.sub.2 released from the cycle can be vented to a CO.sub.2 pipeline at the desired molar purities with little to no additional post-treatment. However, when the fuel contains elevated concentrations of sulfur and nitrogen, and/or when air ingress to the system is relatively high, combustion temperatures and high temperatures at the hot end of the plant oxidizes the fuel as well as any other oxidize-able compounds and may produce acid gases such as NO.sub.x and/or SO.sub.x that must be removed to protect both process equipment and to satisfy mandated CO.sub.2 pipeline purity levels.

(34) In one example, a system 50 is configured, in a manner as described herein, with a first and second mass transfer column. The first mass transfer column is incorporated into the recycling fluid stream, and treats and selectively removes SO.sub.2 from the recycling fluid. At the entrance of the first mass transfer column, NO is injected into the recycling fluid stream via any suitable process at a steady flow rate, and is adjusted so as to control the complete removal of SO.sub.2 within the first mass transfer column given the residence time provided. In one exemplary embodiment, the NO injection rate is about 46.67 lb/hr and utilizes ammonia oxidation over a catalyst. Within the first mass transfer column, at a pressure of approximately 30 bar and at a temperature of about 60 F. to about 200 F., SO.sub.2 is removed and the majority of NO is allowed to exit with the working fluid and thus recirculate within the process thereby resulting in an elevated system-wide concentration of NO. This elevated concentration of NO has the implication of accelerating SO.sub.2 removal within the first mass transfer column.

(35) The second mass transfer column operates at the outlet of the power generation system at a pressure of approximately 30 bar and at approximately an ambient temperature. In particular, the second mass transfer column removes residual NO in the working fluid to a desired concentration, such as approximately 20 ppm. Computer simulations of the example system have been completed, and the results and relevant inputs such as the residence time and inlet and outlet concentrations of NO and SO.sub.2 are shown in Table 1 below. The results and relevant inputs shown in Table 1 below are intended for to be exemplary in purpose and are not intended to limit the scope of the present disclosure. Results disclosed herein are not intended to be interpreted as concrete expectations, but merely indications of an approximated result (i.e., the amount of SO.sub.x (molfrac) leaving the second mass transfer column, 1.39E-20, indicates that there is substantially zero amount of SO.sub.x leaving the second mass transfer column).

(36) TABLE-US-00001 TABLE 1 Properties of First and Second Direct Contact Reactor Mass Transfer Columns in a Power Generation System First direct contact sec Required 30 reactor mass transfer Residence column Time Second direct contact sec Required 22.2 reactor mass transfer Residence column Time NO.sub.x Addition lbmol_NO/ Injected NO 1.5553 hr lb_NO/hr Injected NO 46.6685495 First direct contact lb/hr Total NO at 780.744945 reactor mass transfer Inlet column Total SO.sub.2 at 14458.5508 Inlet Outlet NO 780.474244 Outlet SO.sub.2 0.000263097 Mol fraction NO In 0.000151911 SO.sub.2 In 0.00131764 NO.sub.x Out 0.000155385 SO.sub.x Out 2.45E11 lb/hr Total Mass 7335076.8 Flow Out Second direct contact lb/hr Inlet NO.sub.x 44.1640181 reactor mass transfer Inlet SO.sub.x 1.49E05 column Outlet NO.sub.x 8.44E15 Outlet SO.sub.x 5.6701554 Mol fraction NO.sub.x In 0.000155632 SO.sub.x In 2.46E11 NO.sub.x Out 2.00E05 SO.sub.x Out 1.39E20 lb/hr Total Mass 413664.494 Flow Out

(37) Although increasing the injection rate of NO into the recirculating process gas stream would decrease the required residence time in the first direct contact reactor mass transfer column for total SO.sub.2 removal, a balance between the variable cost of pumping duty, NO addition, neutralization, and the capital cost of column size exists, which will ultimately determine the residence time required for optimum SO.sub.2 removal speed and costs.

(38) Many modifications and other embodiments of the invention will come to mind to one skilled in the art to which this invention pertains having the benefit of the teachings presented in the foregoing descriptions and associated drawings. Therefore, it is to be understood that the invention is not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.